**UNITEDSTATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

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**FORM 10-Q**

**x**                              QUARTERLYREPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACTOF 1934

**Forthe quarterly period ended June 30, 2007**

**or**

**o**                                 TRANSITIONREPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACTOF 1934

**Forthe transition periodfrom                    to                    **

**CommissionFile Number: 0-6910**

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**TELOFFSHORE TRUST**

(Exact name of registrantas specified in its charter)

| **Texas**                                              |   | **76-6004064**       |
|--------------------------------------------------------|--------|----------------------|
| (State or other  jurisdiction of                       |   | (I.R.S. Employer     |
| incorporation, or  organization)                       |   | Identification  No.) |
| **The Bank of New York Trust  Company, N.A., Trustee** |   | ** **           |
| **919  Congress Avenue**                               |   | ** **           |
| **Austin,  Texas**                                     |   | **78701**            |
| (Address of principal  executive offices)              |   | (Zip Code)           |

 

**(800) 852-1422**

(Registrant’s telephonenumber, including area code)

Indicate by check markwhether the registrant (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrant was required tofile such reports), and (2) has been subject to such filing requirementsfor the past 90 days. Yes x    No o

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, or anon-accelerated filer. See definition of “accelerated filer and largeaccelerated filer” in Rule 12b-2 of the Exchange Act.

(Checkone):    Large Accelerated Filer o    Accelerated Filer o    Non-acceleratedfiler x

Indicate by check markwhether the registrant is a shell company (as defined in Rule 12b-2of the Exchange Act). Yes o    No x

Indicatethe number of shares outstanding of each of the issuer’s classes of commonstock, as of the latest practicable date. As of August 14, 2007—4,751,510Units of Beneficial Interest in TEL Offshore Trust.

 

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**NOTE REGARDINGFORWARD-LOOKING STATEMENTS**

This Form 10-Q includes “forward-lookingstatements” within the meaning of Section 27A of the Securities Act of1933, as amended, and Section 21E of the Securities Exchange Act of 1934,as amended. All statements other than statements of historical facts includedin this Form 10-Q are forward-looking statements. Although the WorkingInterest Owners (as defined herein) have advised the Trust that they believethat the expectations reflected in the forward-looking statements containedherein are reasonable, no assurance can be given that such expectations willprove to have been correct. Important factors that could cause actual resultsto differ materially from expectations (“Cautionary Statements”) are disclosedin this Form 10-Q, including, without limitation, in conjunction with theforward-looking statements included in this Form 10-Q. A summary ofcertain principal risks and Cautionary Statements is also included in the Trust’sAnnual Report on Form 10-K for the year ended December 31, 2006 underPart I, Item 1A. “Risk Factors.” All subsequent written and oral forward-lookingstatements attributable to the Trust or persons acting on its behalf areexpressly qualified in their entirety by the Cautionary Statements.

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**PART I—FINANCIALINFORMATION**

**Item 1.**                        FinancialStatements.

**TEL OFFSHORE TRUSTSTATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS(Unaudited)**

| ** **                                                                                                                                | ** ** | **June 30,    2007** | ** ** | **December 31,    2006** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------|------------|-----------------------------------------|------------|
| **Assets**                                                                                                                                |       |                                |       |                                    |       |   |   |
| Cash and cash  equivalents                                                                                                                |       | $                                   | 4,029,099  |                                    |       | $ | 3,321,587 |   |   |
| Net overriding  royalty interest in oil and gas properties, net of accumulated amortization  of $28,221,354 and $28,214,149, respectively |       | 46,301                              |       |                                    | 53,506     |   |   |
| Total assets                                                                                                                              |       | $                                   | 4,075,400  |                                    |       | $ | 3,375,093 |   |   |
| **Liabilities  and Trust Corpus**                                                                                                         |       |                                |       |                                    |       |   |   |
| Distribution  payable to Unit holders                                                                                                     |       | $                                   | 2,053,933  |                                    |       | $ | 1,697,721 |   |   |
| Reserve for  future Trust expenses                                                                                                        |       | 1,975,166                           |       |                                    | 1,623,866  |   |   |
| Commitments and  contingencies                                                                                                            |       |                                |       |                                    |       |   |   |
| Trust corpus  (4,751,510 Units of beneficial interest authorized and outstanding)                                                         |       | 46,301                              |       |                                    | 53,506     |   |   |
| Total liabilities and  Trust corpus                                                                                                       |       | $                                   | 4,075,400  |                                    |       | $ | 3,375,093 |   |   |

 

**STATEMENTS OFDISTRIBUTABLE INCOME(Unaudited)**

| ** **                                                | ** ** | **Three Months Ended  June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|-----------------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                                | ** ** | **2007**                                        | ** ** | **2006**                                      | ** ** | **2007** | ** ** | **2006** | ** ** |
| Royalty income                                            |       | $                                               | 2,415,521  |                                          | $          | — |   | $ | 3,932,205 |   | $ | — |   |
| Interest income                                           |       | 18,216                                          |       | 3,990                                         |       | 36,255 |   | 8,782 |   |
|                                                      |       | 2,433,737                                       |       | 3,990                                         |       | 3,968,460 |   | 8,782 |   |
| (Increase)  decrease in reserve for future Trust expenses |       | (97,276                                         | )          | 188,829                                       |       | (351,303 | ) | 353,219 |   |
| General and  administrative expenses                      |       | (282,528                                        | )          | (192,819                                      | )          | (395,650 | ) | (362,001 | ) |
| Distributable  income                                     |       | $                                               | 2,053,933  |                                          | $          | — |   | $ | 3,221,507 |   | $ | — |   |
| Distributions per Unit  (4,751,510 Units)                 |       | $                                               | .432270    |                                          | $          | .000000 |   | $ | .677997 |   | $ | .000000 |   |

 

The accompanying notes are an integral part of these financial statements.

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**STATEMENTS OFCHANGES IN TRUST CORPUS(Unaudited)**

| ** **                                       | ** ** | **Three Months Ended  June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|--------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                       | ** ** | **2007**                                        | ** ** | **2006**                                      | ** ** | **2007** | ** ** | **2006** | ** ** |
| Trust corpus,  beginning of period               |       | $                                               | 49,533     |                                          | $          | 61,580 |   | $ | 53,506 |   | $ | 64,069 |   |
| Distributable  income                            |       | 2,053,933                                       |       | —                                        |       | 3,221,504 |   | — |   |
| Distribution  payable to Unit holders            |       | 2,053,933                                       |       | —                                        |       | 3,221,504 |   | — |   |
| Amortization of  net overriding royalty interest |       | (3,232                                          | )          | (1,966                                        | )          | (7,205 | ) | (4,455 | ) |
| Trust corpus, end of  period                     |       | $                                               | 46,301     |                                          | $          | 59,614 |   | $ | 46,301 |   | $ | 59,614 |   |

 

The accompanying notes are an integral part of these financial statements.

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**TEL OFFSHORE TRUST**

**NOTES TO FINANCIALSTATEMENTS**

**(Unaudited)**

**Note 1—TrustOrganization**

Tenneco Offshore Company, Inc. (“Tenneco Offshore”)created the TEL Offshore Trust (“Trust”) effective January 1, 1983,pursuant to the Plan of Dissolution (“Plan”) approved by Tenneco Offshore’sstockholders on December 22, 1982. In accordance with the Plan, the TELOffshore Trust Partnership (“Partnership”) was formed in which the Trust owns a99.99% interest and Tenneco Oil Company (“Tenneco”) initially owned a .01% interest.In general, the Plan was effected by transferring an overriding royaltyinterest (“Royalty”) equivalent to a 25% net profits interest in the oil andgas properties (the “Royalty Properties”) of Tenneco Exploration, Ltd. (“ExplorationI”) located offshore Louisiana to the Partnership and issuing certificatesevidencing units of beneficial interest in the Trust (“Units”) in liquidationand cancellation of Tenneco Offshore’s common stock.

On October 31, 1986, Exploration I was dissolvedand the oil and gas properties of Exploration I were distributed to Tennecosubject to the Royalty. Tenneco, who was then serving as the Managing GeneralPartner of the Partnership, assumed the obligations of Exploration I, includingits obligations under the instrument conveying the Royalty to the Partnership(the “Conveyance”). The dissolution of Exploration I had no impact onfuture cash distributions to holders of units of beneficial interest.

On November 18, 1988, Chevron U.S.A., Inc. (“Chevron”)acquired most of the Gulf of Mexico offshore oil and gas properties of Tenneco,including all of the Royalty Properties. As a result of the acquisition,Chevron replaced Tenneco as the Working Interest Owner and Managing GeneralPartner of the Partnership. Chevron also assumed Tenneco’s obligations underthe Conveyance.

On October 30, 1992, PennzEnergy Company (“PennzEnergy”)(which merged with and into Devon Energy Production Company L.P. effective January 1,2000) acquired certain oil and gas producing properties from Chevron, includingfour of the Royalty Properties. The four Royalty Properties acquired byPennzEnergy were East Cameron 354, Eugene Island 348, Eugene Island 367 andEugene Island 208. As a result of such acquisition, PennzEnergy replacedChevron as the Working Interest Owner of such properties on October 30,1992. PennzEnergy also assumed Chevron’s obligations under the Conveyance withrespect to these properties.

On December 1, 1994, Texaco Exploration andProduction Inc. (“TEPI”) acquired two of the Royalty Properties fromChevron. The Royalty Properties acquired by Texaco were West Cameron 643 andEast Cameron 371. As a result of such acquisitions, TEPI replaced Chevron asthe Working Interest Owner of such properties on December 1, 1994. TEPIalso assumed Chevron’s obligations under the Conveyance with respect to theseproperties.

On October 1, 1995, SONAT Exploration Company (“SONAT”)acquired the East Cameron 354 property from PennzEnergy. In addition, on October 1,1995, Amoco Production Company (“Amoco”) acquired the Eugene Island 367property from PennzEnergy. As a result of such acquisitions, SONAT and Amocoreplaced PennzEnergy as the Working Interest Owners of the East Cameron 354 andEugene 

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Island 367 properties,respectively, on October 1, 1995 and also assumed PennzEnergy’sobligations under the Conveyance with respect to these properties.

Effective January 1, 1998, Energy ResourceTechnology, Inc. (“ERT”) acquired the East Cameron 354 property fromSONAT. As a result of such acquisition, ERT replaced SONAT as the WorkingInterest Owner of the East Cameron 354 property effective January 1, 1998,and also assumed SONAT’s obligations under the Conveyance with respect to suchproperty. In October 1998, Amerada Hess Corporation (“Amerada”) acquiredthe East Cameron 354 property from ERT effective January 1, 1998. As aresult of such acquisition, Amerada replaced ERT as the Working Interest Ownerof the East Cameron 354 property effective January 1, 1998, and alsoassumed ERT’s obligations under the Conveyance with respect to this property.

Effective January 1, 2000 PennzEnergy and DevonEnergy Corporation (Nevada) merged into Devon Energy Production Company L.P. (“Devon”).As a result of such merger, Devon replaced PennzEnergy as the Working InterestOwner of Eugene Island 348 and Eugene Island 208 properties effective January 1,2000, and also assumed PennzEnergy’s obligations under the Conveyance withrespect to these properties. The abandonment obligations for Eugene Island 348have been assumed by Maritech Resources, Inc. effective January 1,2005.

On October 9, 2001, a wholly owned subsidiary ofChevron Corporation, a Delaware corporation, merged (the “Merger”) with andinto Texaco Inc., a Delaware corporation (“Texaco”), pursuant to anAgreement and Plan of Merger, dated as of October 15, 2000. As a result ofthe Merger, Texaco Inc. became a wholly owned subsidiary of ChevronCorporation, and Chevron Corporation changed its name to “ChevronTexacoCorporation” in connection with the Merger Effective May 9, 2005,ChevronTexaco Corporation changed its name to Chevron Corporation. Accordingly,the properties referred to herein by Chevron and Texaco are each now controlledby subsidiaries of Chevron Corporation.

On May 1, 2002, TEPI assigned all of its interestsin West Cameron 643 and East Cameron 371 to Chevron. Accordingly, pursuant tothe Conveyance of the Royalty Properties, Net Proceeds will be calculated forthe collective Royalty Properties owned by Chevron after this date.

On June 6, 2003, Anadarko Petroleum Corporation (“Anadarko”)acquired, among other interests, a 25% Working Interest in the EastCameron 354 field subject to the Royalty from Amerada effective April 1,2003. As a result of this transaction, Anadarko replaced Amerada as the WorkingInterest Owner of East Cameron 354 effective July 1, 2003 and alsoassumed Amerada’s obligations under the Conveyance with respect to thisproperty.

Effective October 1, 2004, Apache acquiredAnadarko’s interest in East Cameron 354 and assumed Anadarko’s obligationsunder the conveyance with respect to this property.

All of the Royalty Properties continue to be subjectto the Royalty, and it is anticipated that the Trust and the Partnership, ingeneral, will continue to operate as if the above-described sales of theRoyalty Properties had not occurred.

Unless the context in which such terms are usedindicates otherwise, in these Notes to Financial Statements the terms “WorkingInterest Owner” and “Working Interest Owners” generally refer to the owner orowners of the Royalty Properties (Exploration, I through October 31,1986; Tenneco for periods from October 31, 1986 until November 18,1988; Chevron with respect to all Royalty Properties for periods 

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from November 18,1988 until October 30, 1992, and with respect to all Royalty Propertiesexcept East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island208 for periods from October 30, 1992 until December 1, 1994, andwith respect to the same properties except West Cameron 643 thereafter;PennzEnergy/Devon with respect to East Cameron 354, Eugene Island 348, EugeneIsland 367 and Eugene/Devon Island 208 for periods from October 30, 1992until October 1, 1995, and with respect to Eugene Island 348 and EugeneIsland 208 thereafter; TEPI with respect to West Cameron 643 and East Cameron371 for periods beginning on or after December 1, 1994 until May 1,2002; SONAT with respect to East Cameron 354 for periods beginning on or after October 1,1995; Amoco with respect to Eugene Island 367 for periods beginning on or afterOctober 1, 1995; Amerada with respect to East Cameron 354 for periodsbeginning on or after January 1, 1998 until July 1, 2003; Chevronwith respect to West Cameron 643 and East Cameron 371 on and after May 1,2002; Anadarko with respect to East Cameron 354 on and after July 1, 2003until October 1, 2004; and Apache with respect to East Cameron 354after October 1, 2004).

The Trust is currentlyadministered by The Bank of New York Trust Company, N.A., which succeededJPMorgan Chase Bank, N.A. as the Corporate Trustee, effective October 2,2006 pursuant to an agreement under which The Bank of New York acquiredsubstantially all of the Corporate Trust business of JPMorgan Chase (formerlyknown as The Chase Manhattan Bank), and Daniel O. Conwill, IV,Gary C. Evans and Jeffrey S. Swanson (“Individual Trustees”), astrustees (“Trustees”).

**Note 2—Basisof Accounting**

The accompanying unaudited financial information hasbeen prepared by The Bank of New York Trust Company, N.A. (“CorporateTrustee”) in accordance with the instructions to Form 10-Q. Theaccompanying financial information is prepared on a comprehensive basis of accountingother than accounting principles generally accepted in the United States ofAmerica. The Corporate Trustee and the individual trustees (collectively, the “Trustees”)believe that the disclosures are adequate to make the information presented notmisleading. The information furnished reflects all adjustments which are, in theopinion of the Trustees, necessary for a fair presentation of the results forthe interim periods presented. The financial information should be read inconjunction with the financial statements and notes thereto included in theTrust’s Annual Report on Form 10-K for the year ended December 31,2006.

The financialstatements of the Trust are prepared on the following basis:

(a)          Royalty income isrecorded when received, including the effect of overtaken or undertakenpositions and negative or positive adjustments, by the Corporate Trustee on thelast business day of each calendar quarter. In addition, Royalty incomeincludes amounts related to funds deposited or released from the Special CostEscrow account—see (c); and

(b)         Trust general andadministrative expenses are recorded when paid, except for the cash reservedfor future general and administrative expenses; and

(c)          The funds deposited orreleased from the Special Cost Escrow account are recorded at the time ofpayment or receipt. The Special Cost Escrow account is an account of theWorking Interest Owners and is not reflected in the financial statements of theTrust.

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This manner of reporting income and expenses isconsidered to be the most meaningful because the quarterly distributions toUnit holders are based on net cash receipts received from the Working InterestOwners. The financial statements of the Trust differ from financial statementsprepared in accordance with generally accepted accounting principles, because,under such principles, Royalty income and Trust general and administrativeexpenses for a quarter would be recognized on an accrual basis. In addition,amortization of the net overriding royalty interest, which is calculated on aunits-of-production basis, is charged directly to Trust corpus since suchamount does not affect distributable income.

Cash and cash equivalents include all highly liquid,short-term investments with original maturities of three months or less.

The changes in reserve for future Trust expensesincludes both changes of amounts deemed necessary by the Trustees and relateddistributions, as well as amounts paid from the reserve during periods when theTrust has insufficient income to pay Trust expenses.

The Trust reviews the net overriding royalty interestin oil and gas properties for possible impairment whenever events orcircumstances indicate the carrying amount of the asset may not be recoverable.If there is an indication of impairment, the Trust prepares an estimate offuture cash flows (undiscounted and without interest charges) expected toresult from the use of the asset and its eventual disposition. If these cashflows are less than the carrying amount of the asset, an impairment loss may berecognized to write down the asset to the lower of its estimated fair value ornet book value. Preparation of estimated expected future cash flows isinherently subjective and is based on the Corporate Trustee’s best estimate ofassumptions concerning expected future conditions. There were no write downstaken in the periods presented.

The Special Cost Escrow account (Note 5) isestablished for the future costs to be incurred to plug and abandon wells,dismantle and remove platforms, pipelines and other production facilites andfor the estimated amount of future capital expenditures on the RoyaltyProperties. The funds held in the Special Cost Escrow account are not reflectedin the financial statements of the Trust. However, funds deposited to orreleased from the Special Cost Escrow account are included in Royalty income.

The preparation of financial statements requires theTrustees to make use of estimates and assumptions that affect amounts reportedin the financial statements as well as certain discounts. Actual results coulddiffer from those estimates.

The amount of cashdistributions by the Trust is dependent on, among other things, the salesprices for oil and gas produced from the Royalty Properties and the quantitiesof oil and gas sold. It should be noted that substantial uncertainties existwith regard to future oil and gas prices, which are subject to materialfluctuations due to changes in production levels and pricing and other actionstaken by major petroleum producing nations, as well as the regional supply anddemand for gas, weather, industrial growth, conservation measures, competitionand other variables. The Trust does not enter into any hedging transactions onfuture production.

**Note 3—NetOverriding Royalty Interest**

The Royalty entitles theTrust to its share (99.99%) of 25% of the Net Proceeds attributable to theRoyalty Properties. The Conveyance, dated January 1, 1983, provides thatthe Working Interest Owners 

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willcalculate, for each period of three months commencing the first day ofFebruary, May, August and November, an amount equal to 25% of the NetProceeds from their oil and gas properties for the period. Generally, “NetProceeds” means the amounts received by the Working Interest Owners from thesale of minerals from the Royalty Properties less operating and capital costsincurred, management fees and expense reimbursements owing to the ManagingGeneral Partner of the Partnership, applicable taxes other than income taxes,and a Special Cost Escrow account. The Special Cost Escrow account (SeeNote 5) is established for the future costs to be incurred to plug andabandon wells, dismantle and remove platforms, pipelines and other productionfacilities, and for the estimated amount of future capital expenditures on theRoyalty Properties. Net Proceeds do not include amounts received by the WorkingInterest Owners as advance gas payments, “take-or-pay” payments or similarpayments unless and until such payments are extinguished or repaid through thefuture delivery of gas.

**Note 4—Distributionsto Unit Holders**

In accordance with the provisions of the TrustAgreement, generally all Net Proceeds received by the Trust, net of Trustgeneral and administrative expenses and any cash reserves established for thepayment of contingent or future obligations of the Trust, are distributedcurrently to the Unit holders. Such distributions are referred to as “distributableincome.” The amounts distributed are determined on a quarterly basis and arepayable to Unit holders of record as of the last business day of each calendarquarter. However, cash distributions are made in January, April, July and October andinclude interest earned from the quarterly record date to the date ofdistribution.

During 2005, HurricaneKatrina and Hurricane Rita caused significant damage to various platforms andthird-party transportation systems which resulted in oil and gas productiondelays in the Royalty Properties. During 2006 several of the platforms andfacilities on the Royalty Properties were restored; however, certain projectsremain to be completed during 2007 to increase production to pre-hurricanelevels. The Trust may have to fund its share of project costs and other relatedexpenditures that are not covered by insurance of the operator of the RoyaltyProperties. Further delays in repairs on third-party transportation systems maycontinue to limit production. Additionally, the extensive damage caused bythese hurricanes has led to significant demand for services and supplies forrepairs in the offshore Gulf of Mexico, which has increased current and futurelevels of expenditures. The reduced oil and gas production and increased costsreduced the cash income distributions to unitholders significantly during 2006and may continue to affect cash income distributions during a portion or all of2007. During the fourth quarter 2006, the Trust resumed distributions. Thefourth quarter distribution of $1.7 million was paid on January 11,2007. On June 27, 2007, the Trust announced its second quarterdistribution of approximately $2.0 million.

**Note 5—Special CostEscrow Account**

The Special Cost Escrow is an account of the WorkingInterest Owners, and it is described herein for informational purposes only.The Conveyance provides for the reserve of funds for estimated future “SpecialCosts” of plugging and abandoning wells, dismantling platforms and other costsof abandoning the Royalty Properties, as well as for the estimated amount offuture drilling projects and other capital expenditures on the RoyaltyProperties. As provided in the Conveyance, the amount of funds to be reservedis determined based on certain factors, including estimates of aggregate futureproduction costs, 

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aggregate future SpecialCosts, aggregate future net revenues and actual current net profits interest.Deposits into this account reduce current distributions and are placed in anescrow account and invested in short-term certificates of deposit. Such accountis herein referred to as the “Special Cost Escrow” account. The Trust’s shareof interest generated from the Special Cost Escrow account serves to reduce theTrust’s share of allocated production costs. Special Cost Escrow funds willgenerally be utilized to pay Special Costs to the extent there are not adequatecurrent net profits interest to pay such costs. Special Costs that have beenpaid are no longer included in the Special Cost Escrow calculation. Deposits tothe Special Cost Escrow account will generally be made when the balance in theSpecial Cost Escrow account is less than 125% of estimated future Special Costsand there is a Net Revenues Shortfall (a calculation of the excess of estimatedfuture costs over estimated future net revenues pursuant to a formula containedin the Conveyance). When there is not a Net Revenues Shortfall, amounts in theSpecial Cost Escrow account will generally be released, to the extent thatSpecial Costs have been incurred. Amounts in the Special Cost Escrow accountwill also be released when the balance in such account exceeds 125% ofestimated future Special Costs. In the second quarter of 2007, there was a netrelease of funds from the Special Cost Escrow account of approximately$304,000. As of June 30, 2007, $7,341,867 remained in the Special CostEscrow account. The funds held in the Special Cost Escrow account are notreflected in the financial statements of the Trust.

Chevron, in its capacityas Managing General Partner of the Partnership, has advised the Trust thatadditional deposits to the Special Cost Escrow account may be required infuture periods in connection with other production costs, other abandonment costs,other capital expenditures and changes in the estimates and factors describedabove. Such deposits could result in a significant reduction in Royalty incomein the periods in which such deposits are made, including the possibility thatno Royalty income would be received in such periods.

**Note 6—ReserveFor Future Trust Expenses**

The Trust made a determination in 1998 to maintain acash reserve equal to approximately three times the average expenses of theTrust during each of the past three years to provide for future administrativeexpenses in connection with the winding up of the Trust. During the first sixmonths of 2007, the Trust increased its reserve by $351,303 for a reservebalance of $1,975,166 as of June 30, 2007. The reserve amount at June 30,2006 was $1,010,984.

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**Item 2.**                        Management’sDiscussion and Analysis of Financial Condition and Results of Operations.

**Critical AccountingPolicies**

The financialstatements of the Trust are prepared on the following basis:

(a)          Royalty income isrecorded when received, including the effect of overtaken or undertakenpositions and negative or positive adjustments, by the Corporate Trustee on thelast business day of each calendar quarter. In addition, Royalty incomeincludes amounts related to funds deposited or released from the Special CostEscrow account—see (c); and

(b)         Trust general andadministrative expenses are recorded when paid, except for the cash reservedfor future general and administrative expenses; and

(c)          The funds deposited orreleased from the Special Cost Escrow account are recorded at the time ofpayment or receipt. The Special Cost Escrow account is an account of theWorking Interest Owners and is not reflected in the financial statements of theTrust.

This manner of reporting income and expenses isconsidered to be the most meaningful because the quarterly distributions toUnit holders are based on net cash receipts received from the Working InterestOwners. The financial statements of the Trust differ from financial statementsprepared in accordance with generally accepted accounting principles, because,under such principles, Royalty income and Trust general and administrativeexpenses for a quarter would be recognized on an accrual basis. In addition,amortization of the net overriding royalty interest, calculated on aunits-of-production basis, is charged directly to Trust corpus since suchamount does not affect distributable income.

The Trustees, includingthe Corporate Trustee, have no authority over, have not evaluated and make nostatement concerning, the internal control over financial reporting of theWorking Interest Owners.

**Financial Review**

**Three Months Ended June 30,2007 and 2006**

There were distributions of $2,053,933 or $0.432270per Unit to the Unit holders for the three months ended June 30, 2007 ascompared to no distributions for the same period in 2006. There was nodistributable income for the second quarter of 2006 primarily as a result ofdamages caused to the Royalty Properties by Hurricanes Rita and Katrinadiscussed below in “—Operational Review” and a required deposit to the SpecialCost Escrow account.

Crude oil and condensate revenues increased$2,462,719, or 46%, to $7,863,691 in the second quarter of 2007 as compared to$5,400,972 in the second quarter of 2006, due to a 52% increase in crude oiland condensate volume to 135,984 barrels in the second quarter of 2007 from89,309 barrels in the second quarter of 2006. The increase is partially offsetby a 4% decrease in the average price of crude oil and condensate to $57.83 perbarrel in the second quarter of 2007 from $60.47 per barrel in the secondquarter of 2006.

Gas revenues increased$2,268,349, or 9,790%, to $2,291,518 in the second quarter of 2007 from $23,169in the second quarter of 2006, due to an increase in gas volumes of 108,919% to289,797 Mcf in the second quarter of 2007 from 2,654 Mcf in the second quarterof 2006, offset by a 9% decrease in the average price received for natural gasto $7.91 per Mcf in the second quarter of 2007 from $8.73 per Mcf in 

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thesecond quarter of 2006. Gas products revenue increased $134,014 to $136,230 inthe second quarter of 2007 from $2,216 in the second quarter of 2006, dueprimarily to an increase in production volume of 144,776 gallons to 147,254gallons in the second quarter of 2007 from 2,478 gallons in the second quarterof 2006.

The increase in crude oiland condensate volume, as well as natural gas volumes and gas productsproduction volumes, for the three months ended June 30, 2007 compared tothe three months ended June 30, 2006 resulted primarily from repairs ofcertain damages caused by Hurricanes Rita and Katrina.

The Trust’s share ofcapital expenditures decreased $5,413,225, or 95%, from $5,654,409 in thesecond quarter of 2006 to $241,184 in the second quarter of 2007. The higher amountof capital expenditures for the second quarter of 2006 related primarily todamages caused by Hurricanes Rita and Katrina.

The Royalty Properties did not have undistributed netincome as of June 30, 2007.

In the second quarter of 2007, there was a net releaseof funds into the Special Cost Escrow account. The Trust’s share of the netfunds released was $300,403 As of June 30, 2007, $7,341,867 remained inthe Special Cost Escrow account. The Special Cost Escrow is set aside forestimated abandonment costs and future capital expenditures, as provided for inthe Conveyance. For additional information relating to the Special Cost Escrow,see “—Special Cost Escrow Account”, below.

In the second quarter of2006, there was no deposit of funds into the Special Cost Escrow account.

**Six Months Ended June 30,2007 and 2006**

There were distributions of $3,221,507 or $0.677997per Unit to the Unit holders for the six months ended June 30, 2007as compared to no distributions for the same period in 2006. There was nodistributable income for the first six months of 2006 primarily as a result ofdamages caused to the Royalty Properties by Hurricanes Rita and Katrinadiscussed below in “—Operational Review” and a required deposit to the SpecialCost Escrow account.

Crude oil and condensate revenues increased$6,525,026, or 60%, to $17,563,175 in the first six months of 2007 ascompared to $11,038,148 for the same period in 2006, due to a 57% increase incrude oil and condensate volume to 295,990 barrels in the first six months of2007 from 188,917 barrels in the first six months of 2006, as well as anincrease in the average price of crude oil and condensate from $58.43 perbarrel to $59.34 per barrel during these periods.

Gas revenues increased $4,220,705, to $4,804,006 inthe first six months of 2007 from $583,301 for the same period in 2006, due toan increase in gas volumes of 515% to 661,059 Mcf in the first six months of2007 from 107,415 Mcf for the same period in 2006 in addition to a 9% increasein the average price received for natural gas to $7.27 per Mcf in the first sixmonths of 2007 from $6.72 per Mcf in the same period of 2006. Gas productsrevenue increased $184,409, or 165%, to $296,517 in the first six months of2007 from $112,108 in the same period of 2006, primarily due to an increase inproduction volume of 197,419 gallons, or 137%, to 341681 gallons in the firstsix months of 2007 from 144,262 gallons in the same period of 2006.

The increase in crude oil and condensate volume, aswell as natural gas volumes and gas products production volume, for the firstsix months of 2007 compared to the first six months of 2006 resulted primarilyfrom repairs of certain damages caused by Hurricanes Rita and Katrina.

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The Trust’s share ofcapital expenditures decreased $6,207,252, from $7,381,976 in the first sixmonths of 2006 to $1,174,724 in the same period of 2007. The higher amount ofcapital expenditures for the first six months of 2006 related primarily todamages caused by Hurricanes Rita and Katrina.

The Royalty Proprieties didnot have undistributed net income as of June 30, 2007.

In the first six months of2007, there was a net deposit of funds into the Special Cost Escrow account.The Trust’s share of the net funds deposited was $504,778. In the first sixmonths of 2006, there was a net deposit of funds into the Special Cost Escrowaccount. The Trust’s share of the net funds deposited was $880,238. As of June 30,2007, $7,341,867 remained in the Special Cost Escrow account. The Special CostEscrow is set aside for estimated abandonment costs and future capitalexpenditures, as provided for in the Conveyance. For additional informationrelating to the Special Cost Escrow, see “—Special Cost Escrow Account”, below.

**Reserve for FutureTrust Expenses**

In accordance with theprovisions of the Trust Agreement, generally all Royalty income received by theTrust, net of Trust general and administrative expenses and any cash reservesestablished for the payment of contingent or future obligations of the Trust,are distributed currently to the Unit holders. In the first quarter of 1998,the Trust determined that the Trust’s cash reserve was sufficient at that timeto provide for future administrative expenses in connection with the winding upof the Trust. The Trust determined that a cash reserve equal to approximatelythree times the average expenses of the Trust during each of the past threeyears was sufficient at this time to provide for future administrative expensesin connection with the winding up of the Trust. During the second quarter of2007, the Trust increased its reserve by $97,276 for a reserve balance of$1,975,166 as of June 30, 2007. The reserve amount at June 30, 2006was $1,010,984.

**Other**

The amount of cashdistributed by the Trust is dependent on, among other things, the sales pricesand quantities of oil and gas produced from the Royalty Properties as well ascapital expenditures by the Working Interest Owners that may or may not beincluded in the Special Cost Escrow account. It should be noted thatsubstantial uncertainties exist with regard to future oil and gas prices, whichare subject to material fluctuations due to changes in production levels andpricing and other actions taken by major petroleum producing nations, as wellas the regional supply and demand for oil and gas, weather, industrial growth,conservation measures, competition and other variables.

**Operational Review**

At the end of October 2005,approximately half of Chevron oil-equivalent production in the Gulf of Mexicoremained shut in due to damages from hurricanes in the third quarter. The timeit will take to resume this production is uncertain, and some of the volumesmay not be sufficiently economic to restore. As of July 13, 2007, EugeneIsland 339 gas sales line was repaired and gas sales were resumed. The WorkingInterest Owner has also advised the Trust that the Working Interest Owner hascompleted the project to compress and re-inject gas to the B-5 well, whichallows the operator to increase oil production and to limit flaring of gas.Eugene Island 339 oil production increased during the third quarter of 2006 andincreased further during the fourth quarter of 2006 and the first quarter 2007as the B-5 well gas injection 

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projectwas completed. On Ship Shoal 182/183, gas production and sales resumed in July 2006and full production resumed in the fourth quarter of 2006. On West Cameron 643,production was shut in from September 2005 following Hurricane Rita’smajor damage to various platforms, but limited gas production resumed in late July 2006before the wells loaded up and additional repairs were required thus requiringthe well to be shut in again during the second quarter 2006.

**Three Months Ended June 30, 2007 and 2006**

The following operationalinformation has been based on information provided to the Corporate Trustee byChevron as the Managing General Partner of the Partnership and by theapplicable Working Interest Owners. The Trustees have no control over theseoperations or internal controls relating to this information.

*Volumes and dollar amounts discussed below representamounts recorded by the Working Interest Owners unless otherwise specified.*

Ship Shoal 182/183 crudeoil revenues increased from $3,632,946 in the second quarter of 2006 to$3,738,186 in the second quarter of 2007, primarily due to an increase in netcrude oil production from 59,190 barrels in the second quarter of 2006 to63,161 barrels in the second quarter of 2007. The increase was partially offsetby a decrease in the average crude oil price from $61.38 per barrel in thesecond quarter of 2006 to $59.19 per barrel for the same period in 2007. Gasrevenues increased from $0 in the second quarter of 2006 to $2,251,252 in thesecond quarter of 2007 due to the repair of damages caused by Hurricanes Ritaand Katrina that caused gas production to go offline during the second quarter2006 compared to production of 284,259 Mcf in the second quarter of 2007. ShipShoal 182/183 did experience a reduction in the rate of production during thesecond quarter of 2007 due to temporary high pipeline pressures. The averagegas sales price during the second quarter of 2007 was $7.92 per Mcf. Capitalexpenditures decreased from $4,050,969 in the second quarter of 2006 to$107,114 in the second quarter of 2007 primarily due to the completion of therepair and upgrade work on the platforms associated with damages caused byHurricanes Rita and Katrina. Operating expenses increased from $472,293 in thesecond quarter of 2006 to $861,367 for the same period in 2007 due to increasedproduction.

Eugene Island 339 netcrude oil revenues increased from $1,648,164 in the second quarter of 2006 to$3,989,800 for the same period in 2007 due to an increase in volumes from28,130 barrels in the second quarter of 2006 to 70,494 barrels in the secondquarter of 2007. The increase in production was partially offset by a decreasein the average crude oil price from $58.59 per barrel in the second quarter of2006 to $56.60 per barrel in the second quarter of 2007. Gas revenues were $0 inthe second quarter of 2006 and in the second quarter of 2007 due to damagescaused by Hurricanes Rita and Katrina that caused gas production to remain at 0Mcf for both quarters. Capital expenditures decreased from $1,602,231 in thesecond quarter of 2006 to $74,636 in the second quarter of 2007 primarily dueto repairs associated with hurricane-related damages. Operating expensesdecreased from $369,461 in the second quarter of 2006 to $297,167 in the secondquarter of 2007.

West Cameron 643 gasrevenues were $0 in the second quarter of 2006 and 2007 due to damages causedby Hurricanes Rita and Katrina and a temporary shut in during 2007 that causedgas production to remain at 0 Mcf in the second quarter of 2006 and 2007.Operating expenses increased from $48,892 in the second quarter of 2006 to$302,985 for the same period in 2007 due to platform and facility repairs, andcapital expenditures remained flat from $1 in the second quarter of 2006 to $0for the same period in 2007.

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East Cameron 371 crude oilrevenues were $0 in the second quarter of 2006 and 2007 due to the field beingshut in. Gas revenues were $0 for the second quarter of 2006 and 2007 also dueto the temporary shut in of the field. Capital expenditures were were $0 forthe second quarter 2006 and 2007. Operating expenses increased from $4,168 inthe second quarter of 2006 to $14,524 for the same period in 2007.

**Six Months Ended June 30,2007 and 2006**

*Volumes and dollaramounts discussed below represent amounts recorded by the Working InterestOwners unless otherwise specified.*

Ship Shoal 182/183 crude oil revenues increased from$8,229,579 in the first six months of 2006 to $8,677,306 in the same period in2007, primarily due to an increase in net crude oil production from 135,746barrels in the first six months of 2006 to 139,922 in the same period of 2007and an increase in the average crude oil price from $60.92 per barrel in thefirst six months of 2006 to $62.02 per barrel for the same period in 2007. Gasrevenues increased from $0 in the first six months of 2006 to $4,484,899 in thesame period of 2007. Gas production increased from 0 Mcf in the first sixmonths of 2006 to 604,835 Mcf in the same period of 2007 due to the repair ofhurricane-related damages. There were no natural gas sales and thus no averagesales price in the first six months of 2006 compared to $7.42 per Mcf due tothe repair of hurricane-related damages. Capital expenditures decreased from$4,769,031 in the first six months of 2006 to $578,023 in the same period of2007 primarily due to a decrease in hurricane-related repairs. Operatingexpenses increased from $1,011,352 in the first six months of 2006 to$1,851,959 for the same period in 2007 due to wells coming back online and thusincreased production.

Eugene Island 339 net crude oil revenues increasedfrom $2,589,854 in the first six months of 2006 to $8,606,245 for the sameperiod in 2007, due to an increase in volumes from 49,429 barrels in the firstsix months of 2006 to 151,305 barrels in the first six months of 2007. Theaverage crude oil prices increased from $52.40 per barrel in the first sixmonths of 2006 to $56.88 per barrel for the same period in 2007. Gas revenuesdecreased from $547,819 in the first six months 2006 to $0 for the same periodin 2007, due to a decrease in natural gas volumes from 83,101 Mcf in the firstsix months of 2006 to 0 Mcf for the same period in 2007. Capital expendituresdecreased from $2,565,014 in the first six months of 2006 to $129,741 in thesame period in 2007, due to a decrease in repairs of hurricane-related damages.Operating expenses increased from $576,198 in the first six months of 2006 to$887,768 in the same period in 2007.

West Cameron 643 gas revenues increased from $0 in thefirst six months of 2006 to $219,217 for the period in 2007. This is due to anincrease in gas volumes from 0 Mcf in the first six months of 2006 to 42,094Mcf for the same period in 2007. Operating expenses increased from $217,908 forthe first six months of 2006 to $525,420 for the same period in 2007, andcapital expenditures decreased from $46,156 for the first six months of 2006 to$0 for the same period in 2007.

East Cameron 371 crude oilrevenues were $0 for the second quarter 2006 and 2007. Gas revenues increasedfrom $0 for the first six months of 2006 to $14,724 for the same period in2007. Capital expenditures were $0 in the first six months of 2006 and 2007.Operating expenses increased from $8,201 in the first six months of 2006 to$26,830 for the same period in 2007.

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**Future Net Revenuesand Termination of the Trust**

Based on a reserve studyprovided to the Trust by DeGolyer and MacNaughton, independent petroleumengineers, as of October 31, 2006 future net revenues attributable to theTrust’s royalty interests were estimated at $38.3 million. Estimates ofproved oil and gas reserves attributable to the Partnership’s royalty interestare based on existing economic and operating conditions in effect at October 31,2006 in order to correspond with distributions to the Trust. Such reserve studyalso indicates that approximately 72% of the future net revenues from theRoyalty Properties are expected to be received by the Trust during the nextthree years. In addition, because the Trust will terminate in the event estimatedfuture net revenues fall below $2.0 million, it would be possible for theTrust to terminate even though some or all of the Royalty Properties continuedto have remaining productive lives. Upon termination of the Trust, the Trusteeswill sell for cash all of the assets held in the Trust estate and make a finaldistribution to Unit holders of any funds remaining after all Trust liabilitieshave been satisfied. The estimates of future net revenues discussed above aresubject to large variances from year to year and should not be construed asexact. There are numerous uncertainties present in estimating future netrevenues for the Royalty Properties. The estimate may vary depending on changesin market prices for crude oil and natural gas, the recoverable reserves,annual production and costs assumed by DeGolyer and MacNaughton. In addition,future economic and operating conditions as well as results of future drillingplans may cause significant changes in such estimate. The discussion set forthabove is qualified in its entirety by reference to the Trust’s Annual Report onForm 10-K for the year ended December 31, 2006. The Trust’s Form 10-Kis available at the website of the Securities and Exchange Commission (“SEC”)at *www.sec.gov* or upon requestfrom the Corporate Trustee.

**Special Cost EscrowAccount**

The Conveyance provides for reserving funds forestimated future “Special Costs” of plugging and abandoning wells, dismantlingplatforms and other costs of abandoning the Royalty Properties, as well as forthe estimated amount of future drilling projects and other capital expenditureson the Royalty Properties. As provided in the Conveyance, the amount of fundsto be reserved is determined based on factors including estimates of aggregatefuture production costs, aggregate future Special Costs, aggregate future netrevenues and actual current net proceeds. Deposits into this account reducecurrent distributions and are placed in an escrow account and invested inshort-term certificates of deposit. Such account is herein referred to as the “SpecialCost Escrow” account. The Trust’s share of interest generated from the SpecialCost Escrow account serves to reduce the Trust’s share of allocated productioncosts.

Special Cost Escrow funds will generally be utilizedto pay Special Costs to the extent there are not adequate current net proceedsto pay such costs. Special Costs that have been paid are no longer included inthe Special Cost Escrow calculation. Deposits to the Special Cost Escrowaccount will generally be made when the balance in the Special Cost Escrowaccount is less than 125% of estimated future Special Costs and there is a NetRevenues Shortfall (a calculation of the excess of estimated future costs overestimated future net revenues pursuant to a formula contained in theConveyance). When there is not a Net Revenues Shortfall, amounts in the SpecialCost Escrow account will generally be released, to the extent that SpecialCosts have been incurred. Amounts in the Special Cost Escrow account will alsobe released when the balance in such account exceeds 125% of estimated futureSpecial Costs. In the first six months 

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of 2007, there was a netdeposit of funds to the Special Cost Escrow account of $504,778. In the firstsix months of 2006, there was a net deposit of funds to the Special Cost Escrowaccount of $880,238.

As of June 30, 2007, $7,341,867 remained in theSpecial Cost Escrow account.

Chevron, in its capacityas Managing General Partner of the Partnership, has advised the Trust that additionaldeposits to the Special Cost Escrow account may be required in future periodsin connection with other production costs, other abandonment costs, othercapital expenditures and changes in the estimates and factors described above.Such deposits could result in a significant reduction in Royalty income in theperiods in which such deposits are made, including the possibility that noRoyalty income would be received in such periods.

**Overview of Production, Prices and Royalty Income**

The following scheduleprovides a summary of the volumes and weighted average prices for crude oil andcondensate and natural gas recorded by the Working Interest Owners for theRoyalty Properties, as well as the Working Interest Owners’ calculations of theNet Proceeds and the royalties paid to the Trust during the periods indicated.Net Proceeds due to the Trust are calculated for each three-month periodcommencing on the first day of February, May, August and November.

| ** **                                                   | ** ** | **Royalty Properties  Three Months Ended  June 30,(1)** | ** ** |
|--------------------------------------------------------------|------------|-----------------------------------------------------------------------------|------------|
| ** **                                                   | ** ** | **2007**                                                                    | ** ** | **2006** | ** ** |
| Crude oil and condensate  (bbls)                             |       | 135,984                                                                     |       | 89,309 |   |
| Natural gas and gas  products (Mcfe)                         |       | 310,833                                                                     |       | 3,008 |   |
| Crude oil and condensate  average price, per bbl             |       | $                                                                           | 57.83      |   | $ | 60.47 |   |
| Natural gas average  price, per Mcf (excluding gas products) |       | $                                                                           | 7.91       |   | $ | 8.73 |   |
| Crude oil and condensate  revenues                           |       | $                                                                           | 7,863,691  |   | $ | 5,400,972 |   |
| Natural gas and gas  products revenues                       |       | 2,427,749                                                                   |       | 25,385 |   |
| Production expenses                                          |       | (1,876,584                                                                  | )          | (1,271,653 | ) |
| Capital expenditures                                         |       | (241,184                                                                    | )          | (5,654,409 | ) |
| Undistributed net loss  (income)(2)                          |       | —                                                                      |       | 1,515,733 |   |
| Refund of (provision  for) Special Cost Escrow               |       | 1,489,376                                                                   |       | (16,028 | ) |
| **Net Proceeds**                                             |       | $                                                                           | 9,663,048  |   | $ | — |   |
| Royalty interest                                             |       | x25                                                                         | %          | x25 | % |
| Partnership share                                            |       | $                                                                           | 2,415,762  |   | $ | — |   |
| Trust interest                                               |       | x99.99                                                                      | %          | x99.99 | % |
| Trust share of Royalty  Income                               |       | $                                                                           | 2,415,521  |   | $ | — |   |

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(1)          Amounts represent actualproduction for the three-month period ended April of each yearrespectively.

(2)          Undistributednet loss represents negative Net Proceeds generated during the respectiveperiod. An undistributed net loss is carried forward and offset, in futureperiods, by positive Net Proceeds earned by the related Working InterestOwner(s). Undistributed net income represents positive Net 

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Proceeds, generated during the respective period, thatwere applied to an existing loss carryforward. As of June 30, 2007, theloss carryforward was $0. 

| ** **                                                   | ** ** | **Royalty Properties  Six Months Ended  June 30,** | ** ** |
|--------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                   | ** ** | **2007**                                                               | ** ** | **2006** | ** ** |
| Crude oil and  condensate (bbls)                             |       | 295,989                                                                |       | 188,917 |   |
| Natural gas and  gas products (Mcfe)                         |       | 709,870                                                                |       | 107,415 |   |
| Crude oil and  condensate average price, per bbl             |       | $                                                                      | 59.34      |   | $ | 58.43 |   |
| Natural gas  average price, per Mcf (excluding gas products) |       | $                                                                      | 7.27       |   | $ | 6.72 |   |
| Crude oil and  condensate revenues                           |       | $                                                                      | 17,563,175 |   | $ | 11,038,148 |   |
| Natural gas and  gas products revenues                       |       | 5,100,523                                                              |       | 695,409 |   |
| Production  expenses                                         |       | (4,171,949                                                             | )          | (2,480,389 |   |
| Capital  expenditures                                        |       | (1,174,724                                                             | )          | (7,381,976 | ) |
| Undistributed net  income(1)                                 |       | (2,092                                                                 | )          | 1,515,733 |   |
| Refund of  (provision for) Special Cost Escrow               |       | (1,584,540                                                             | )          | (3,386,926 | ) |
| **Net  Proceeds**                                            |       | $                                                                      | 15,730,393 |   | $ | — |   |
| Royalty interest                                             |       | x25                                                                    | %          | x25 | % |
| Partnership share                                            |       | $                                                                      | 3,932,598  |   | $ | — |   |
| Trust interest                                               |       | x99.99                                                                 | %          | x99.99 | % |
| Trust share of Royalty  Income                               |       | $                                                                      | 3,932,205  |   | $ | — |   |

 

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(1)          Undistributednet loss represents negative Net Proceeds generated during the respectiveperiod. An undistributed net loss is carried forward and offset, in futureperiods, by positive Net Proceeds earned by the related Working InterestOwner(s). Undistributed net income represents positive Net Proceeds, generatedduring the respective period, that were applied to an existing losscarryforward. As of June 30, 2007, the loss carryforward was $0.

**Item 3.**                        Quantitativeand Qualitative Disclosures About Market Risk.

No material changes haveoccurred since our Annual Report on Form 10-K for the year-ended December 31,2006. Reference is also made to Note 2 of the Notes to FinancialStatements included in Item 1 of this Form 10-Q.

**Item 4.**                        Controlsand Procedures.

*Evaluationof disclosure controls and procedures.   The*Corporate Trustee maintains disclosurecontrols and procedures designed to ensure that information required to bedisclosed by the Trust in the reports that it files or submits under theSecurities Exchange Act of 1934, as amended, is recorded, processed, summarizedand reported within the time periods specified in the SEC’s rules andregulations. Disclosure controls and procedures include controls and proceduresdesigned to ensure that information required to be disclosed by the Trust isaccumulated and communicated by Chevron, as the managing general partner of thePartnership, and the Working Interest Owners to The Bank of New York TrustCompany, N.A., as 

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Corporate Trustee of theTrust, and its employees who participate in the preparation of the Trust’speriodic reports as appropriate to allow timely decisions regarding requireddisclosure.

As of the end of the period covered by this report,the Corporate Trustee carried out an evaluation of the Trust’s disclosurecontrols and procedures. Mike Ulrich, as Trust Officer of the CorporateTrustee, has concluded that the disclosure controls and procedures of the Trustare effective.

Due to the contractual arrangements of (i) theTrust Agreement, (ii) the Partnership Agreement and (iii) the rightsof the Partnership under the Conveyance regarding information furnished by theWorking Interest Owners, the Trustees rely on (A) information provided bythe Working Interest Owners, including historical operating data, plans forfuture operating and capital expenditures, reserve information and informationrelating to projected production, (B) information from the managinggeneral partner of the Partnership, including information that is collectedfrom the Working Interest Owners, and (C) conclusions and reports regarding reserves by theTrust’s independent reserve engineers. See Part I, Item 1A. “Risk Factors—TheTrustees and the Unit holders have no control the over the operation ordevelopment of the Royalty Properties and have litte influence over operationor development” and “—The Trustees rely upon on the working interest owners andmanaging general partner for information regarding the Royalty Properties” inthe Trust’s Annual Report on Form 10-K for the year ended December 31,2006, and “Note 5—Negative Adjustments” of the financial statements and “Management’sDiscussion and Analysis of Financial Condition and Results of Operations”relating to operating information on East Cameron 371 included in the AnnualReport on Form 10-K for the year ended December 31, 2006 for a descriptionof certain risks relating to these arrangements and reliance and applicableadjustments to operating information when reported by the Working InterestOwners to the Corporate Trustee and recorded in the Trust’s results ofoperations.

*Changes in InternalControl Over Financial Reporting.**  *During the three months ended June 30,2007, there has been no change in the Corporate Trustee’s internal control overfinancial reporting that has materially affected, or is reasonably likely tomaterially affect, the Corporate Trustee’s internal control over financialreporting relating to the Trust. The Corporate Trustee notes for purposes ofclarification that it has no authority over, and makes no statement concerning,the internal control over financial reporting of the Working Interest Owners orthe managing general partner of the Partnership.

**PART II—OTHERINFORMATION**

**Item 1A.**                RiskFactors.

There have not been any material changes from riskfactors previously disclosed in the Trust’s response to Item 1A of Part 1of the Trust’s Annual Report on Form 10-K for the year ended December 31,2006.

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**PART II—OTHERINFORMATION**

**Item 6.**                        Exhibits.

(Asteriskindicates exhibit previously filed with the Securities and Exchange Commissionand incorporated herein by reference.) 
|        | ** ** | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                                          | ** ** | **SEC File or  Registration  Number** | ** ** | **Exhibit  Number** |
|--------|------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|---------------------|
| 4(a)*  |       | —     | Trust Agreement  dated as of January 1, 1983, among Tenneco Offshore Company, Inc.,  Texas Commerce Bank National Association, as corporate trustee, and Horace C.  Bailey, Joseph C. Broadus and F. Arnold Daum, as individual trustees  (Exhibit 4(a) to Form 10-K for the year ended  December 31, 1992 of TEL Offshore Trust) |       | 0-6910                                |       | 4(a)                |
| 4(b)*  |       | —     | Agreement of  General Partnership of TEL Offshore Trust Partnership between Tenneco Oil  Company and the TEL Offshore Trust, dated January 1, 1983  (Exhibit 4(b) to Form 10-K for year ended  December 31, 1992 of TEL Offshore Trust)                                                                                                               |       | 0-6910                                |       | 4(b)                |
| 4(c)*  |       | —     | Conveyance of  Overriding Royalty Interests from Exploration I to the Partnership  (Exhibit 4(c) to Form 10-K for year ended  December 31, 1992 of TEL Offshore Trust)                                                                                                                                                                                |       | 0-6910                                |       | 4(c)                |
| 4(d)*  |       | —     | Amendments to TEL  Offshore Trust Agreement, dated December 7, 1984  (Exhibit 4(d) to Form 10-K for year ended  December 31, 1992 of TEL Offshore Trust)                                                                                                                                                                                              |       | 0-6910                                |       | 4(d)                |
| 4(e)*  |       | —     | Amendment to the  Agreement of General Partnership of TEL Offshore Trust Partnership, effective  as of January 1, 1983 (Exhibit 4(e) to Form 10-K  for the year ended December 31, 1992 of TEL Offshore Trust)                                                                                                                                        |       | 0-6910                                |       | 4(e)                |
| 10(a)* |       | —     | Purchase  Agreement, dated as of December 7, 1984 by and between Tenneco Oil  Company and Tenneco Offshore II Company (Exhibit 10(a) to  Form 10-K for year ended December 31, 1992 of  TEL Offshore Trust)                                                                                                                                      |       | 0-6910                                |       | 10(a)               |
| 10(b)* |       | —     | Consent  Agreement, dated November 16, 1988, between TEL Offshore Trust and  Tenneco Oil Company (Exhibit 10(b) to Form 10-K for year  ended December 31, 1988 of TEL Offshore Trust)                                                                                                                                                                      |       | 0-6910                                |       | 10(b)               |
| 10(c)* |       | —     | Assignment and  Assumption Agreement, dated November 17, 1988, between Tenneco Oil  Company and TOC-Gulf of Mexico Inc. (Exhibit 10(c) to  Form 10-K for year ended December 31, 1988 of  TEL Offshore Trust)                                                                                                                                    |       | 0-6910                                |       | 10(c)               |
| 10(d)* |       | —     | Gas Purchase and  Sales Agreement Effective September 1, 1993 between Tennessee Gas  Pipeline Company and Chevron U.S.A. Production Company  (Exhibit 10(d) to Form 10-K for year ended  December 31, 1993 of TEL Offshore Trust)                                                                                                                          |       | 0-6910                                |       | 10(d)               |
| 31     |       | —     | Certification  furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                                                                                                                             |       |                                  |       |                |
| 32     |       | —     | Certification furnished  pursuant to Section 906 of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                                                                                                                             |       |                                  |       |                |

 

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**SIGNATURES**

Pursuantto the requirements of the Securities Exchange Act of 1934, the Registrant hasduly caused this report to be signed on its behalf by the undersigned thereuntoduly authorized.
|              | TEL OFFSHORE  TRUST |
|--------------|---------------------|
|         | By:                 | The Bank of New York  Trust Company, N.A.,  Corporate Trustee |
|         | By:                 | /s/  MIKE ULRICH |
| *** *** | ** **          | ***Mike  Ulrich  Vice President*** |

 

Date: August 14, 2007

The Registrant, TEL Offshore Trust, has no principalexecutive officer, principal financial officer, board of directors or personsperforming similar functions. Accordingly, no additional signatures areavailable and none have been provided.

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